Carbon capture solvents having alcohols and amines and methods for using such solvents

ABSTRACT

Methods and compositions useful, for example, for physical solvent carbon capture. The solvents may include an aqueous mixture of 2-amino-2-methylproponol, 2-piperazine-1-ethylamine, diethylenetriamine, 2-methylamino-2-methyl-1-propanol, and potassium carbonate or potassium carbonate buffer salt. The solvent may also contain less than about 75% by weight of dissolving medium (i.e., water) and may have a single liquid phase. The solvents and methods have favourable regeneration energies, chemical stability, vapour pressure, total heat consumption, net cyclic capacity, and reaction kinetics.

CROSS-REFERENCE TO RELATED APPLICATION DATA

This application is a national stage application, filed under 35 U.S.C.371, of International Patent Application No. PCT/IB2015/001855, filed onAug. 21, 2015, which claims the benefit of priority to U.S. ProvisionalPatent Application Ser. No. 62/040,911, which is incorporated herein byreference.

FIELD OF TECHNOLOGY

This application relates to carbon capture.

BACKGROUND

Separating CO₂ from gas streams has been commercialized for decades infood production, natural gas sweetening, and other processes. Aqueousmonoethanolamine (MEA) based solvent capture is currently considered tobe the best commercially available technology to separate CO₂ fromexhaust gases, and is the benchmark against which future developments inthis area will be evaluated. Unfortunately, amine-based systems were notdesigned for processing the large volumes of flue gas produced by apulverized coal power plant. Scaling the amine-based CO₂ capture systemto the size required for such plants is estimated to result in an 83%increase in the overall cost of electricity from such a plant.

Accordingly, there is always a need for an improved solvent.

SUMMARY

Embodiments described herein include, for example, compounds andcompositions, and methods of making and methods of using the compoundsand compositions. Systems and devices can also be provided which usethese compounds and compositions and relate to the methods. Forillustration, this disclosure relates to a carbon capturing solvent (anexample termed “APBS”) and methods for treating industrial effluentgases using the solvent. The solvent disclosed herein removes CO₂ at amore efficient rate than MEA and degrades at a rate lower than othersolvents (e.g., MEA).

In one embodiment, the composition and method disclosed herein may beimplemented at various types of industrial plants, including powerplants, for example. In one example, the solvent may include an aqueousmixture of 2-amino-2 methylpropanol, 2-piperazine-ethylamine,diethylenetriamine, 2-methylamino-2-methyl-1-propanol, and potassiumcarbonate buffer salt. The composition may also contain less than about75% by weight of a dissolving medium (i.e., water) and may have a singleliquid phase. In another example, the solvent may include an aqueousmixture of an amino hindered alcohol, a polyamine with three or moreamino group and a carbonate buffer salt.

Additional features of the present disclosure will become apparent tothose skilled in the art upon consideration of the following detaileddescription exemplifying the best mode for carrying out the disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of compositions, systems, and methods are illustrated in thefigures of the accompanying drawings which are meant to be exemplary andnot limiting, in which like references are intended to refer to like orcorresponding parts, and in which:

FIG. 1 illustrates APBS vapor liquid equilibrium data at 40 C and 120 Cto determine CO2 loading (mol/L) versus the partial pressure of CO₂(kPa);

FIG. 2 illustrates APBS solvent vapor liquid equilibrium data ascompared to MEA according to the present disclosure;

FIG. 3 illustrates a flow-scheme of a carbon capture pilot according tothe present disclosure;

FIG. 4 illustrates corrosion/solvent metal content of MEA (30 wt. %) andAPBS according to the present disclosure;

FIG. 5 illustrates ammonia emissions during a pilot plant campaignaccording to the present disclosure;

FIG. 6 illustrates an aerosol particle size distribution according tothe present disclosure;

FIG. 7 illustrates the effect of L/G ratios on regeneration efficiencyaccording to the present disclosure;

FIG. 8 illustrates the effect of stripper pressure on regenerationefficiency according to the present disclosure; and

FIG. 9 illustrates methane recovery using a solvent according to thepresent disclosure.

DEFINITIONS

As used herein, the term “solvent” can refer to a single solvent or amixture of solvents and may be used interchangeable with the term“composition.”

DETAILED DESCRIPTION

The detailed description of aspects of the present disclosure set forthherein makes reference to the accompanying drawings and pictures, whichshow various embodiments by way of illustration. The detaileddescription herein is presented for purposes of illustration only andnot of limitation. For example, the steps recited in any of the methodor process descriptions may be executed in any order and are not limitedto the order presented. Moreover, references to a singular embodimentmay include plural embodiments, and references to more than onecomponent may include a singular embodiment.

Generally, this disclosure provides a composition and a method of usingthe composition to reduce or eliminate CO₂ emissions from a processstream, e.g., as coal-fired power plants, which bum solid fuels. Thesolvent and method disclosed herein capture/sequester CO₂ from fluegases. The flue gases may be generated by gas and oil-fired boilers,combined cycle power plants, coal gasification, and hydrogen and biogasplants.

In one embodiment, a solvent has an amino hindered alcohol with vaporpressure less 0.1 kPa at 25 C and a polyamine with three or more aminogroups with vapor pressure less 0.009 kPa at 25 C, and a carbonatebuffer to buffer the solvent to a pH greater than 8 (e.g., a pH of about8, about 10, or about 13). The solvent can have a vapor pressure lessthan 1.85 kPa at 25 C.

In another embodiment, a polyamine with vapor pressure less than 0.009kPa at 25 C (e.g., as 2-Piperazine-1-ethylamine or diethylenetriamine)creates resiliency to aerosol phase emissions due to very low pressure,which may result of carbamate reaction with CO₂. The amino hinderedalcohol with vapor pressure less 0.1 kPa at 25 C will form aerosol phaseemissions due to a carbonate/bicarbonate reaction with CO2. In aspecific embodiment, a hindered alcohol with a polyamine with low vaporpressure (0.009) yields less than 32 mg/Nm3 aerosol formation. In aspecific embodiment, a hindered alcohol with a polyamine with low vaporpressure (0.009) yields less than 28 mg/Nm3 aerosol formation. In otherembodiments, a hindered alcohol with a polyamine with low vapor pressure(0.009) yields more than half of aerosols being less than 32 mg/Nm3. Inanother embodiment, a hindered alcohol with a polyamine with low vaporpressure (0.009) yields more than half of the aerosols being less than28 mg/Nm3.

In one example, the solvent may include an aqueous solution of2-amino-2-methylproponol, 2-Piperazine-1-ethylamine, diethylenetriamine,2-methylamino-2-methyl-1-propanol, and potassium carbonate. The solventand method have favorable solvent regeneration (i.e., amount of inputenergy is low), chemical stability, vapor pressure, total heatconsumption, net cyclic capacity, and reaction kinetics. The solvent andmethod also result in low emission of aerosols and nitrosamines, andsubstantially no foaming.

In one example, the solvent comprises an amino hindered alcohol having avapor pressure less than 0.1 kPa at 25 C, a polyamine with three or moreamino groups having vapor pressure less 0.009 kPa at 25 C, and acarbonate buffer. The solvent has a vapor pressure less than 1.85 kPa at25 C. The polyamine can be 2 piperazine-1-ethylamine anddiethylenetriamine together, and the amino hindered alcohol can be 2methylamino-2-methyl-1-propanol, and 2-amino-2-methylproponol together.

For illustration, 2-amino-2-methylproponol and 2methylamino-2-methyl-1-propanol propanol are sterically hinderedalcohols that have low absorption heats, high chemical stabilities, andrelatively low reactivity. Piperazine-1-ethylamine anddiethylenetriamine have very high, fast kinetics and are chemicallystable under the conditions disclosed herein. Piperazine-1-ethylamineand diethylenetriamine have very low volatilities, which reduceenvironmental concerns of the disclosed solvent. Piperazine-1-ethylamineand diethylenetriamine may act as promoters for 2-amino-2-methylproponoland 2-methylamino-2-methyl-1-propanol to provide high absorptionactivity and fast reaction kinetics.

The CO₂ solvent may contain a carbonate buffer. A pH range for thecarbonate buffer may be between about 8.0 and about 13. The presence ofthe carbonate buffer can increase the pH of the solvent. A pH of about8.0 to about 9.0 allows for increased CO₂ capture in the form ofbicarbonate salts. The carbonate buffer may be regenerated when thesolvent is heated. For example, percarbonate may be utilized.

Carbonate buffer salts may also be used. The amount of carbonate buffersalt used should be sufficient to raise salivary pH to about 7.8 ormore, about 8.5 or more, or about 9 or more (e.g., about 9 to about 11),irrespective of the starting ph. Thus, the amount of carbonate buffersalt used in the solvent will depend upon implementation conditions. Inan example, the carbonate buffer salt may be sodium carbonate, potassiumcarbonate, calcium carbonate, ammonium carbonate, or magnesiumcarbonate.

Bicarbonate salts may also be used. Exemplary bicarbonate salts include,for example, sodium bicarbonate, potassium bicarbonate, calciumbicarbonate, ammonium bicarbonate, and magnesium bicarbonate.

Binary buffer compositions may additionally be utilized. An exemplarybinary buffer composition includes a combination of sodium carbonate andsodium bicarbonate. In an example, the sodium bicarbonate of the solventmay be desiccant-coated sodium bicarbonate.

An amount of carbonate buffer and amine promoter in the solvent may belimited by the solubility of both components in water, resulting in asolid solubility limit for aqueous solutions. For example, at 25 C, thesolubility of potassium carbonate buffer in a CO₂ rich solution is 3.6m. With the solid solubility limitation, the resulting lowerconcentration can result in a slow reaction rate and low solutioncapacity. By combining piperazine-1-ethylamine, diethylenetriamine, andcarbonate buffer, for example, the resultant solubility increases.

When promoter absorbent amines such as Piperazine-1-ethylamine andDiethylenetriamine reach with CO₂, an equilibrium reaction occurs toform carbamate and dicarbamate and some free and bound promoter amines.Because of the addition of carbonate buffer salt, which reacts with freeand bound promoter amines, the equilibrium reaction is driven tocompletion, thereby resulting in more CO₂ absorption.

In an example, the solvent contains 2-amino-2-methylproponol in anamount of about 10 wt % to about 32 wt %, about 11 wt % to about 28 wt%, and preferably in an amount of about 13 wt % to about 25 wt %. Whenabout 12 vol % CO₂ is experienced at the inlet of a flue gas CO₂ capturesystem, about 19.5 wt % of 2-amino-2-methylproponol may be desirable.When about 4 vol % CO₂ is experienced at the inlet of a flue gas CO₂capture system, about 13.3 wt % of 2-amino-2-methylproponol may bedesirable. When about 40 vol % CO₂ is experienced at the inlet of abiogas CO₂ capture system, about 24.2 wt % of 2-amino-2-methylproponolmay be desirable.

In another example, the solvent contains 2-Piperazine-1-ethylamine in anamount of about 10 wt % to about 35 wt %, about 12 wt % to about 30 wt%, and preferably in an amount of about 14 wt % to about 28 wt %. Whenabout 12 vol % CO₂ is experienced at the inlet of a flue gas CO₂ capturesystem, about 22.4 wt % of 2-Piperazine-1-ethylamine may be desirable.When about 4 vol % CO₂ is experienced at the inlet of a flue gas CO₂capture system, about 27.6 wt % of 2-Piperazine-1-ethylamine may bedesirable. When about 40 vol % CO₂ is experienced at the inlet of abiogas CO₂ capture system, about 15.15 wt % of 2-Piperazine-1-ethylaminemay be desirable.

In a further example, the solvent contains diethylenetriamine in anamount of about 0.1 wt % to about 4 wt %, about 0.1 wt % to about 3 wt%, and preferably in an amount of about 0.1 wt % to about 0.35 wt %.When about 12 vol % CO₂ is experienced at the inlet of a flue gas CO₂capture system, about 0.2 wt % of diethylenetriamine may be desirable.When about 4 vol % CO₂ is experienced at the inlet of a flue gas CO₂capture system, about 0.35 wt % of Diethylenetriamine may be desirable.When about 40 vol % CO₂ is experienced at the inlet of a biogas CO₂capture system, about 0.1 wt % of diethylenetriamine may be desirable.

In yet another example, the solvent contains2-Methylamino-2-methyl-1-propanol in an amount of about 0.8 wt % toabout 5 wt %, about 1 wt % to about 2.8 wt %, and preferably in anamount of about 1.2 wt % to about 1.8 wt %. When about 12 vol % CO₂ isexperienced at the inlet of a flue gas CO₂ capture system, about 1.5 wt% of 2-Methylamino-2-methyl-1-propanol maybe desirable. When about 4 vol% CO₂ is experienced at the inlet of a flue gas CO₂ capture system,about 1.2 wt % of 2-methylamino-2-methyl-1-propanol may be desirable.When about 40 vol % CO₂ is experienced at the inlet of a biogas CO₂capture system, about 1.8 wt % of 2-methylamino-2-methyl-1-propanol maybe desirable.

In an additional example, the solvent contains buffer (e.g., potassiumcarbonate) in an amount of about 0.1 wt % to about 6 wt %, about 0.2 wt% to about 3 wt %, and preferably in an amount of about 0.5 wt % toabout 1.0 wt %. When about 12 vol % CO₂ is experienced at the inlet of aflue gas CO₂ capture system, about 0.5 wt % of potassium carbonate maybe desirable. When about 4 vol % CO₂ is experienced at the inlet of aflue gas CO₂ capture system, about 0.7 wt % of potassium carbonate maybe desirable. When about 40 vol % CO₂ is experienced at the inlet of abiogas CO₂ capture system, about 0.4 wt % of potassium carbonate may bedesirable.

Characteristics of the solvent play a major role in determining bothequipment size and process energy requirements. In certaincircumstances, the following factors can be considered when choosing asolvent:

-   -   Regeneration energy: since the exothermic reactions taking place        in the absorber are reversed by addition of heat in a reboiler,        a solvent having a low or lower heat of absorption is desirable;    -   Cyclic capacity (the difference between CO₂ concentration in the        solvent leaving the absorber and that leaving the reboiler): a        solvent having a high or higher cyclic capacity is desirable        since higher cyclic capacities result in a lower rebolier duty,        reduced electrical consumption in pumps, and possible downsizing        of equipment, which results in lower investment costs;    -   Evaporation loss: a solvent has high evaporation loss, a water        wash section is needed on top of the absorber. Thus, a solvent        having a low evaporation loss is desirable, thereby eliminating        the need for a water wash section;    -   Solubility in water: amines with bulky non-polar parts showing        limited solubility in water. Thus, a solvent having amines        soluble in water is desirable;    -   Chemical stability: a solvent that is not vulnerable to        oxidative degradation is desired. A problem with MEA is its        vulnerability towards oxidative degradation when exposed to an        exhaust gas;    -   Corrosivity: the solvent, as well as its possible degradation        products, should exhibit limited corrosivity;    -   Foaming: if not controlled, foaming may lead to gas cleaning and        mal-distribution of liquid flow in the absorption tower, thus        reducing its performance. Accordingly, a solvent exhibiting        minimal to no foaming is desirable;    -   Toxicity and environment impact: a solvent exhibiting minimal to        no toxicity and environmental impact is desirable; and    -   Aerosol and nitrosamine emissions: since aerosols and        nitrosamine are volatile, a solvent exhibiting minimal to no        production of aerosols and nitrosamine is desirable.        Certain exemplary solvents have characteristics with respect to        the aforementioned criteria compared to other solvents (e.g.,        MEA), presently accepted industry standard. These        characteristics are exemplified through the below detailed        experiments involving MEA as a reference solvent. Certain        solvents disclosed herein has low energy requirements and good        chemical stability. The method of using the solvent disclosed        herein makes use of the solvent's characteristics, resulting in        the method having a low energy consumption with minimal        environment impact. Other benefits of the disclosed solvent and        method will become apparent in light of the description set        forth herein.        A variety of container, absorber, or tower devices as known in        the art can be used for the contacting step. The size and shape,        for example, can be varied. The container can have one or more        input ports and one or more exit ports. For example, the        contacting step can be carried out in an absorption column. In        the contacting step, a gas such as the first composition can be        passed through a liquid composition such as the second        composition. One can adapt the parameters to achieve a desired        percentage of carbon dioxide capture such as, for example, at        least 70%, or at least 80%, or at least 90% carbon dioxide        capture. Recycling can be carried out where solvent is looped        back into a reactor for further processing. In one embodiment,        after the contacting step, the second composition with its        dissolved carbon dioxide is subjected to one or more carbon        dioxide removal steps to form a third composition which is        further contacted with a first composition comprising carbon        dioxide. Other known processing steps can be carried out. For        example, filtering can be carried out. As known in the art,        pumps, coolers, and heaters can be used.        A contacting step can be part of a larger process flow with        other steps both before and after the contacting step. For        example, membrane separation steps can also be carried out as        part of the larger process. For example, PBI membranes can be        used. The contacting step can be also part of a larger process        in which components are removed. In some preferred embodiments,        the contacting step is part of a carbon capture process. For        example, an IGCC plant and carbon capture are described in in        the literature. As known in the art, pre-combustion capture        processes and compression cycles can be carried out. Continuous        or batch processing can be carried out. The contacting step        results in at least partial dissolution of the carbon dioxide of        the first composition in the second composition.

EXAMPLES AND EXPERIMENTS

The following examples illustrate methods and embodiments in accordancewith the invention.

Screening

In certain examples, a mini-vapor-liquid equilibrium (“VLE”) setup wasused to test exemplary solvents. The mini-VLE setup included six (6)apparatuses in parallel. The 6 apparatuses were capable of beingoperated at different temperatures. Different combinations of solventcomponents and concentrations were screened at 40 C and 120 C. Thesesolvents components screened were 2-amino-2-methylproponol,2-Piperazine-1-ethylamine, Diethylenetriamine,2-Methylamino-2-methyl-1-propanol, potassium carbonate, piperazine,2-methyl piperazine, N-ethyl ethanolamine, and N-methyl diethanolamine.

VLE Measurements Using Autoclave

VLE measurements demonstrate the relationship between partial pressureof CO₂ in the vapor phase and the loading (i.e., concentration) of CO₂in a solvent at different temperatures. An autoclave apparatus used toperform VLE testing is described. The autoclave includes a glass vessel,a stirrer, a pH sensor, and pressure sensors. The volume of the vesselwas 1 liter. Prior to commencing the experiment, pressure was broughtdown to −970 mbar using a vacuum pump. 0.5 liter of solvent was added tothe vessel and was heated up so equilibrium could be determined at aconstant temperature of the solvent. VLE was determined at several CO₂partial pressures and temperatures.

At the start of the experiment, a CO₂ pulse was performed. A subsequentpulse was performed only if the following two conditions were satisfied:(1) the time between two pulses was at least 45 minutes; and (2) theaverage pressure value of 5 minutes of data did not deviate by more than1 mbar from the average value of 5 other minutes of data points 15minutes earlier. The latter condition ensured the subsequent pulse wasonly given when the pressure was stabilized. The pressure measured inthe vessel at t=0 s was subtracted from pressures measured after the CO₂pulses. At higher temperatures, the vapor pressure of the solvent(measured in a separate experiment) was subtracted from the measuredpressures.

FIGS. 4 and 6 show results of the aforementioned VLE testing. Thepartial pressure of CO₂ in the vapor phase increased with temperaturefor a given CO₂ loading in the solvent. The points of interest for asolvent based CO₂ capture process are the observed CO₂ loading at “rich”and “lean” solvent conditions. “Lean” solvent is the fresh solvententering the absorber and is ideally free of CO₂. “Rich” solvent is thesolvent leaving the absorber having absorbed as much CO₂ as possible.The two main parameters of a solvent that influence its absorptionperformance are (a) net cyclic capacity (i.e., the difference of richand lean loading); and (b) kinetics due to change in the temperature ofboth lean solvent and flue gas.

As indicated in FIG. 3, the APBS solvent was tested at 40 C and 120 C todetermine vapor equilibrium data of the APBS solvent (i.e., CO₂ loading(mol/L) versus the partial pressure of CO₂ (kPa)). The APBS solvent wasscreened and optimized based on CO₂ vol % at the inlet in resultant fluegases, such as coal (12 vol % CO₂)/gas (4 vol % CO₂) fired flue gasesand biogas (40 vol % CO₂). The CO₂ loading of the solvent increased asthe partial pressure of the CO₂ was increased. However, temperatureplayed a role in the magnitude of CO₂ loading versus the CO₂ partialpressure.

FIG. 5 show a comparison of vapor-liquid equilibrium data of the solventdisclosed herein (APBS 12 vol % CO₂) versus MEA at differenttemperatures (i.e., 40 C and 120 C); under absorber and stripperconditions. The points of interest for a solvent based CO₂ captureprocess are the observed CO₂ loading at “rich” and “lean” solventconditions. “Lean” solvent is the fresh solvent entering the absorberand is ideally free of CO₂. “Rich” solvent is the solvent leaving theabsorber having absorbed as much CO₂ as possible. For a typical coalfired plant (12 vol % CO₂), the CO₂ partial pressure in the exhaust gasstream is about 12 kPa. For a counter current based absorption system,the rich solvent is in contact with this flue gas at the inlet and isdefined as the rich loading. Generally, the temperature of the richsolvent is taken to be 40 C. This leads to a rich loading of 3.3 mol/Lfor 90% CO₂ capture. The CO₂ partial pressure should not be more than 1kPa and thus, the lean loading too should not exceed the correspondingvalue. Based on the VLE measurements, the lean loading of the APBSsolvent at CO₂ partial pressure of 1 kPa is mol/L. Commercially thisdata is very important, as difference of rich and lean loading is theamount of CO₂ captured. For APBS solvents this difference is twice thebenchmark solvent MEA used today, leading to 50% reduction in solventcirculation rates. Lower solvent circulation rates result in lowersolvent circulation cycles, lowering overall energy, degradation, andcorrosion.

Kinetic Measurement of CO₂ Reaction in Aqueous Solvent

Referring to FIG. 7, a device used to determine the kinetics of CO₂reacting with aqueous APBS is described. The device includes a glassstirred cell reactor having a plane and a horizontal gas-liquidinterface used for obtaining absorption rate measurements. The gas andliquid are stirred separately by impellers. The setup was supplied bytwo reservoirs (equipped with heat exchangers), one for the gas phaseand one for the liquid phase.

The rate of absorption as a function of CO₂ partial pressure at varioustemperatures using the device of FIG. 7 are represented in Table 1below.

TABLE 1 Rate of absorption as a function of CO₂ partial pressure atvarious temperatures. APBS (Rc02 × Temperature 106) (C.) Pc02 (kPa)(kmol/(m²sec)) 40 5.4 12.5 50 8.1 24.4 60 7.28 30.4Energy and Reboiler Duty Comparison for MEA and APES/the Solvent

For the CO₂ to be transferred from the liquid phase to the gas phase,there needs to be a driving force on the basis of partial pressure.Steam provides this driving force, resulting in the mass transfer of CO₂from the liquid phase to the gas phase being enhanced. This also hasenergy associated with it, which contributes to the overall reboilerduty. By finding out the amount of water associated with the pure CO₂steam produced (this energy being in the form of water lost that needsto be provided by the reboiler), the amount of energy associated withmass transfer of CO₂ from the liquid phase to the gas phase can bedetermined. The total amount of energy/heat needed to transfer CO₂ fromthe liquid phase to the gas phase is represented byQ _(T) =Q _(sens) +Q _(des) +Q _(strip)  Equation 8

A solvent loaded with CO₂ in the absorber may be heated up to strippertemperature for the regeneration of CO₂. A solvent stream can bepre-heated in the lean-rich cross heat exchanger and then additionalheat may be used to maintain the temperature of a solvent in thestripper (represented by Equation 9).

$\begin{matrix}{Q_{sens} = \frac{\delta\; C_{P}\Delta\; T}{\left( {\alpha_{rich} - \alpha_{lean}} \right)C_{amine}}} & {{Equation}\mspace{14mu} 9}\end{matrix}$

Contributing factors to sensible heat are solvent flow, specific heatcapacity of a solvent, and the temperature increase. Thus, the parameterthat can be varied is one solvent flow, which further depends on theconcentration of one solvent and the one solvent's loadings. This can bedecreased by circulating less solvent and maintaining the same CO₂production rate. This is checked by means of comparing the net capacityof a solvent, which is defined as the difference in the loading atabsorption and desorption conditions.

The CO₂ which is reversibly bound to a solvent needs to be regenerated.The heat of desorption (Q<les) is equivalent to the heat of absorption.The stripping heat is represented by Equation 10.

$\begin{matrix}{Q_{strip} = {\frac{{P_{H\; 2O}^{sat}\left( T_{{top},{des}} \right)}\chi_{{H\; 2O},{freebasis}}}{P_{{CO}\; 2}^{*}\left( {T_{{top},{des}} \cdot \alpha_{rich}} \right)}\Delta\; H_{H\; 2O}^{vap}}} & {{Equation}\mspace{14mu} 10}\end{matrix}$ΔH_(H2O) ^(vap) is the heat of vaporization of water and P*_(CO2) 1s thepartial pressure of CO₂ at equilibrium with the rich solution at thebottom of the absorber.

Table 2 below shows a comparison of the reboiler duty in a typical CO₂capture plant based on 5 M MEA and APBS 12 vol % CO₂ solvent. The totalheat requirement in terms of reboiler duty was 2.3 GJ/ton CO₂ for theAPBS solvent, which is about 30.5% lower than that of MEA (i.e., 3.31GJ/ton CO2).

TABLE 2 Comparison of the reboiler duty in a typical CO₂ capture plantbased on 5M MEA and the APBS 12 vol % solvent. Heat Consumption APBS 12vol % 5M MEA Qsens kJ/kg CO2 140 517 Qdes 1539 1864 Qstrip 555 924.5 QTGJ/ton CO2 2.3 3.31

Pilot Plant Testing—E.ON CO₂ Capture Pilot—Netherlands (6 Tons/Day CO₂Capture

The APBS 12 vol % solvent test campaign was conducted at the E.ON CO₂capture plant in Maasvlakte, Netherlands. The CO₂ capture plant receivesflue gas from unit 2 of the E.ON coal based power station. The captureplant can capture 1210 Nm³/h of flue gas. A schematic representation ofthe capture plant is depicted in FIG. 8. Table 3 below is a legend forthe FIG. 3 schematics and Table 4 provides the main parameters of thecolumns of the E.ON CO₂ capture plant.

TABLE 3 Legend of FIG. 8 CO₂ capture plant schematics. C-01 SO₂- E-01Reboiler P-01 Lean solvent pump scrubber E-02 Condenser P-02 Richsolvent pump C-02 Absorber E-03 Lean-rich HX P-03 Condensate pump C-03Stripper E-04 Lean solvent P-04 Scrubber pump F-01 Filter unit coolerP-05 Wash section pump V-01 Condensate E-05 Wash section K-01 Flue gasfan drum cooler E-06 Scrubber cooler

TABLE 4 Main parameters of the E.ON capture plant columns. SO₂ scrubberAbsorber Stripper Packing height (m) 3 (1 bed) 8 (4 × 2 m) 8 (2 × 4 m)Diameter (m) 0.7 0.65 0.45 Washing Section — 2 1.1 (m) Packing IMTP 50IMTP 50 IMTP 50 Demister — Yorkmesh 172 Yorkmesh 172

Degradation of Unci Corrosion Caused by the APBS Solvent

Table 3. Legend of FIG. 8 CO₂ capture plant schematics.

TABLE 4 Main parameters of the E.ON capture plant columns. SO₂ scrubberAbsorber Stripper Packing height (m) 3 (1 bed) 8 (4 × 2 m) 8 (2 × 4 m)Diameter (m) 0.7 0.65 0.45 Washing Section (m) — 2 1.1 Packing IMTP 50IMTP 50 IMTP 50 Demister — Yorkmesh 172 Yorkmesh 172Degradation of and Corrosion Caused by the APES Solvent

Degradation of solvent often occurs either thermally or due to oxidationin the flue gas. The oxygen content of flue gas from a typical coalfired power plant is about 6% to about 7% by volume. Thermal solventdegradation typically occurs in hot zones such as in the stripper.However, the extent of thermal degradation is lower than oxidativedegradation. Degradation of the solvent leads to loss in activecomponent concentration, corrosion of the equipment by the degradationproducts formed, and ammonia emissions.

Degradation can be observed visually as shown in FIG. 9, which containspictures of MEA and the APBS solvent over the duration of a campaignlasting 1000 operating hours. The color of degraded MEA solution isalmost black while the color of degraded APBS seems to be largelyunchanged from the start of the test campaign to the end. This indicatesthat APBS has higher resistance to degradation than MEA. Also, the APBSsolvent exhibits zero foaming tendency and a high resistivity towardsSO₂ in the flue gas.

As mentioned above, degradation of solvent leads to corrosion of theequipment of CO₂ capture systems. Typically, most of the equipment incontact with the solvent is stainless steel. Thus, based on the amountof metals such as Fe, Cr, Ni, and Mn dissolved in the solvent, it ispossible to estimate the extent of internal plant corrosion. FIG. 4shows the metal content of APB S and MEA during the pilot plantcampaign. The metal content of APBS remained below 1 mg/L, even after1000 operation hours. By comparison, during a previous MEA campaign atthe same pilot plant, metal content of MEA was about 80 mg/L within 600operating hours. Since the metal content of a solvent is correlated withthe amount of equipment corrosion caused by the solvent, this comparisonof APBS and MEA demonstrates that APBS causes less corrosion ofequipment than MEA (which is known by those skilled in the art todegrade rapidly, leading to severe corrosion).

Ammonia (NH₃) is a degradation product of CO₂ capture solvents. Ammonia,since it is volatile, may only be emitted into the atmosphere in smallquantities with CO₂ free flue gas. Consequently, monitoring andminimization of ammonia emission levels is essential. FIG. 5 illustratesmeasured ammonia emission levels of MEA and APBS during thepilot/campaign at the E.ON CO₂ capture plant. For most of the campaign,ammonia emission levels of the APBS solvent were below 10 mg/Nm³. Thisis in stark contrast to the ammonia emission levels of the MEA solvent,which ranged from about 10 mg/Nm³ to about 80 mg/Nm³. Accordingly, APBSis a safer solvent than MEA regarding production and emission of ammoniadue to degradation.

Aerosol of APES Solvent Using Impactor and Impingers

The aerosol box has been installed at a sampling point above the waterwash section of the pilot plant. From preliminary tests it has beendecided to raise the temperature in the aerosol box 1.5 C above thetemperature monitored in the sorption tower and at the measurementlocation, It takes some time for the conditions in the pilot plant tostabilize as the internal temperature of the aerosol box very fast inorder to condition the Anderson cascade impactor. The duration of thefirst measurement was for 63 min. The second measurement was of atlostequal duration (66 min). At the end of 66 min, the impinger sampling wascontinued. In the first measurement the temperature at the samplelocation varied between 39.94 and 41.05 C, while the temperature in theaerosol measurement box varies between 40.8 and 42.2 C. In the secondmeasurement the temperature at the sample location varies between 39.7and 41.4 C and the aerosol bix temperature between 40.7 and 42.2 C.Samples from aerosol trapped from the 28.3 L/min flow through theimpactor stages and collected by adding 5 mL of water to vials with eachone of the filter papers. After shaking the vials, the 8 liquid volumesare added for further analysis by LC-MS.

Table 10 shows the results from the solvent components polyamine and theammo hindered alcohol from impactor (aerosol) droplets and impingers(vapor). As per the results of experiment 1, most of the amines arefound from the impactor. The absolute amount of2-Piperazine-1-ethylamine is as expected. Moreover the ratio of2-amino-2-methylproponol and 2-Piperazine-1-ethylamine is as expected.The results from experiments 2 indicate that more amount of amines ispresent in the impingers rather than the impactor.

This is due to the fact that the second hour of the sampling includedboth aerosols and vapor based emissions. Thus, most of the contributionin the impingers is due to the aerosol component.

The concentration of amines in the droplets collected by the impactor isabout 3 wt. %. Thus, most of content of the droplets is water. This isquite low as compared to MEA aerosols, whose concentration in thedroplets is greater than 50 wt. %. from experiments performed at thepilot plant using a similar method.

TABLE 5 Resiliency of APBS as compared to MEA regarding aerosol solventemissions. 2-amino-2- 2-Piperazine-1- methylproponol ethylamine Exp.Exposure Instrument (mg/Nm3) (mg/Nm ³ ) 1 63 min aerosol Impactor 16.45.6 droplets 63 min vapor Impinger <3 <3 Total 19.4 (max) 8.6 (max) 2 66min aerosol Impactor 8.5 2.5 66 min vapor + 60 Impingers 10 11 minaerosol droplets and vapor Total 18.5 13.5 MEA (mg/Nm3) 3 AerosolImpactor 1580 Vapor Impinger 6.8 Total 1587

The aerosol box separates particles into one of eight stages with aparticle distribution from 0.43 mm to 11 mm. Stage 1 contains thebiggest particles, stage 8 contains the smallest particles. In the firstmeasurement, most aerosol particles were collected on the top threestages with a maximum near 5.8 mm to 9 mm. In the second measurement,most aerosol particles were collected on the top four stages with amaximum near 4.7 mm to 5.8 mm. The total weight collected from all thestages was 421 mg and 690 mg for the first and second experiments,respectively. The corresponding aerosol concentration was 271 mg/Nm³ and423 mg/Nm³ for first and second measurements, respectively. The aerosolparticle size distribution over the eight stages for both measurementsis given in FIG. 6. Overall, this demonstrates that APBS is moreresilient to aerosol production/formation than MEA.

Nitrosamine Emissions of APES Solvent Using Impactor and Impingers

Nitrosamines are known to be carcinogenic. However, nitrosamines arealso present in the environment. Thus, it is important to quantify theextent of nitrosamines accumulated in the solvent and emitted to theatmosphere. Primarily, secondary amines form nitrosamines on

reaction with NO-₃ accumulated in the solvent from the flue gas.However, it is a very tedious

task to list all the specific nitrosamines. Thus, only the totalnitrosamines in the form of the functional group “NNO”. Table 8, thenitrosamine content of the first impinge was below the measuredthreshold, i.e <15 ug/kg, the content for the second impinge is 15ug/kg. A total of <15 ug/kg*0.1 kg+15 ug/kg*0.1 kg is less than 3 ugtotal nitrosamines in the 66+60 min duration of the experiment. Theresulting nitrosamine concentration in the vapor phase at the samplelocation is <4.4 ug/Nm3.

TABLE 6 Nitrosamine content in samples from two impingers placed inseries. Total Nitrosamine Exp Exposure Instrument (ug/Nm³) 1 66 minaerosol Impactor — 66 min vapor + 60 min aerosol First Impinger <2.2droplets and vapor 66 min vapor + 60 min aerosol Second Impinger 2.2droplets and vapor

Pilot Testing—Us-Doe's National Carbon Capture Center (NCCC)—4 Vol % CO₂Flue Gas

The APBS 4 vol % solvent test campaign was conducted at US-DOE's NCCCCO₂ capture pilot plant at the Southern Company in Alabama. The APBSsolvent was specifically developed to capture 3-6 vol % CO₂ from fluegas emissions gas-based power generations.

Apes Testing: 4 Vol % CO₂ NCCC CO₂ Capture Pilot Plant

The APBS testing was conducted from March 2014 to April 2014 andFebruary 2015 to March 2015 for detailed parametric testing and baselineusing state of the art MEA solvent. Table 7 below details a summary ofthe test data collected from the NCCC pilot testing. All of the testinginvolved the following conditions:

(1) APBS solvent;

(2) Wash water flow=10,000 lb/hr;

(3) Wash water section exit gas temperature=110 F;

(4) Three stages of packing (119 was packed with 2 beds);

(5) No inter-stage cooling; and

(6) Steam at 35 psi and 268 F (enthalpy=927 Btu/lb).

TABLE 7 Summary of test data from PSTU at NCCC (all runs with 4.3% CO₂wet). Strip Gas Liquid CO₂ CO₂ Steam/ Energy, P, Flow, Flow, L/G, eff.,Abs., Steam, CO₂, Btu/lb No. Run Date psig lb/hr lb/hr w/w % lb/hr lb/hrlb/lb CO₂ J3 May 1, 2014 9.8 8,000 5,200 0.65 85.5 439.8 718.9 1.631,529.9 J4 May 1, 2014 10.3 8,000 6,000 0.75 88.9 496.0 754.2 1.521,419.5 J5 May 1, 2014 10.0 8,000 6,800 0.85 88.9 458.9 721.3 1.571,469.3 J6 May 2, 2014 12.8 8,000 5,200 0.65 91.4 468.2 713.2 1.521,414.3 17 May 3, 2014 18.3 8,000 5,200 0.65 90.9 466.2 743.6 1.591,472.1 J8 May 5, 2014 23.1 8,000 5,200 0.65 89.3 458.4 743.2 1.621,488.1 J9 May 7, 2014 11.7 8,000 6,000 0.75 90.5 464.5 719.5 1.551,442.8 J10 May 8, 2014 11.7 8,000 6,000 0.75 89.0 457.3 727.1 1.591,480.1 J11 May 8, 2014 11.7 8,000 6,000 0.75 90.7 464.9 729.3 1.571,460.1 J12 May 10, 2014 14.7 8,000 6,000 0.75 90.7 463.2 671.9 1.451,346.8 J13 May 11, 2014 14.9 8,000 6,000 0.75 90.5 464.9 670.1 1.441,337.1 J14 May 12, 2014 14.7 8,000 6,000 0.75 91.9 470.7 696.2 1.481,372.1 J15 May 13, 2014 14.7 8,000 6,000 0.75 92.5 475.6 682.3 1.431,330.9 J16 May 13, 2014 22.6 8,000 6,000 0.75 89.5 458.6 716.6 1.561,437.7 J19 May 15, 2014 22.6 8,000 6,000 0.75 90.4 463.6 763.8 1.641,515.1

Effect of LIG Ratio

The stripper pressure was held constant at 10 psig for runs J3 to 15.The regeneration energy goes through a minima at L/G=0.75 w/w (or 6,000lb/hr liquid flow for 8,000 lb/hr of gas flow). The “smooth curve”minima was at L/G ratio of about 0.76 (w/w) and about 1,416 Btu/lb.Table 8 below details the data plotted in FIG. 7.

TABLE 8 Data plotted in FIG. 7. Strip Gas Liquid CO2 CO2 Steam/ Energy,P, Flow, Flow, L/G, eff., Abs., Steam, CO2, Btu/lb No. Run Date psiglb/hr lb/hr w/w % lb/hr lb/hr lb/lb CO2 J3 May 1, 2014 9.8 8,000 5,2000.65 85.5 439.8 718.9 1.63 1,529.9 14 May 1, 2014 10.3 8,000 6,000 0.7588.9 496.0 754.2 1.52 1,419.5 15 May 1, 2014 10.0 8,000 6,800 0.85 88.9458.9 721.3 1.57 1,469.3Effect of Stripper Pressure

The effect of the stripper pressure on regeneration efficiency is shownin FIG. 8. The L/G ratio was held constant at 0.75 w/w. The regenerationenergy goes through sharp minima at stripper pressure close to 15 psig.The “smooth curve” minima is at stripper pressure of about 14 psig and1,325 Btu/lb CO₂. Table 9 below details the data plotted in FIG. 8.

TABLE 9 Data plotted in FIG. 8. Strip Gas Liquid CO₂ CO₂ Steam/ Energy,P, Flow, Flow, L/G, eff., Abs., Steam, CO2, Btu/lb No. Run Date psiglb/hr lb/hr w/w % lb/hr lb/hr lb/lb CO₂ 19 May 7, 2014 11.7 8,000 6,0000.75 90.5 464.5 719.5 1.55 1,442.8 J15 May 13, 2014 14.7 8,000 6,0000.75 92.5 475.6 682.3 1.43 1,330.9 119 May 15, 2014 22.6 8,000 6,0000.75 90.4 463.6 763.8 1.64 1,515.1Optimal LIG Ratio and Stripper Pressure

The CO₂ absorption efficiency for Run 115 (illustrated in Table 8) was92.5%, which had the minimum energy of regeneration. This shows that theregeneration energy for the conditions of Run 115, but for CO₂ removalefficiency of 90%, would have been about 1,290 Btu/lb CO₂ (or GJ/tonCO₂). From the plots in FIGS. 7 and 8, a global minimum value below1,250 Btu/lb (2.9 GJ/ton CO₂) should be obtained to achieve 90% CO₂capture at NCCC with G=8,000 lb/hr, L/G ratio of 0.76 (or L=6,080lb/hr), and a stripper pressure of 14.5 psig.

Effect of Inter-Cooling

Runs JI6 and JI7 were performed under the same conditions, except runJI7 was carried out with inter-cooling. The regeneration energy reducedonly slightly (less than 0.3%) to 1,434.4 Btu/lb CO₂ with the use ofinter-cooling, suggesting that inter-cooling may not be effective inreducing the regeneration energy for 4 vol % CO₂ flue gas.

Effect of Number of Packed Beds

Runs JI6 and JI9 were performed under the same conditions, except runJI9 was carried out 2 beds. The regeneration energy increased to 1,515.1Btu/lb CO₂ with the use of 2 beds, but the CO₂ removal efficiency wasslightly higher at 90.4% (as against 89.5% for run 116). This shows thatthe APBS solvent of the present disclosure was capable of removing 90%CO₂ with two packed beds (of 6 meter or 20′ packing in PTSU) with about5% more regeneration energy as compared to that required with 3 beds.

Expected Minimum Energy Consumption

The projected regeneration energy for 90% CO₂ capture (1,290 Btu/lb CO₂or 3.0 GJ/ton CO₂) using the solvent of the present disclosure is 35% to40% lower than the values reported for MEA for gas-fired boiler fluegas. However, this is not the lowest achievable value for the APBSsolvent. The PSTU was designed for operation using 30% MEA with theflexibility to accommodate other solvents, but the NCCC lean/rich heatexchanger was not designed for the higher viscosity of the APBS solventrelative to 30% MEA. Thus, the measured approach temperatures during theAPBS solvent test were higher than those for MEA leading to less thanoptimal heat recovery.

Simulations with g-PROMs have predicted that with an optimal lean/richheat exchanger and an advanced stripper design, the minimum regenerationenergy of 1,200 Btu/lb CO₂ (2.8 GJ/ton CO₂) can be achieved for CO₂removal of 90% under the following conditions:

(1) Flue gas with 4.3 vol % CO₂ and 16 vol % 0₂ (G=8,000 lb/hr at PSTU);

(2) Absorber gas velocity=9 ft/sec (PSTU absorber diameter=2′,Area=3.142 ft²

(3) L/G ratio of 0.76 w/w (or L=6,080 lb/hr at PSTU); and

(4) Stripper pressure=14.5 psig.

Effect of Oxygen: Ammonia Emissions (16 Vol % 0₂)

Table 10 illustrates ammonia (NH₃) emissions measured in the vaporstream at the wash water outlet in the PSTU at NCCC for a flue gas with4.3 vol % CO₂ and 16 vol % 0₂ (simulating a natural gas fired boiler).As can be extrapolated, the average ammonia emissions were 3.22 ppm. TheNH₃ emissions measured at the PSTU while treating a flue gas with 11.4vol % CO₂ and 8 vol % 0₂ (from coal-fired boiler) with MEA as thesolvent were 53.7 ppm. This is almost 17 times higher than the averagefor APBS solvent (3.22 ppm), which was measured with almost twice theamount of 0₂ in the flue gas.

TABLE 10 Ammonia emissions with APBS solvent (4.3 vol % CO₂, 16 vol %O₂. Wash Water Outlet Vapor 1 Vapor 2 Vapor 3 NH₃ emissions, ppm 2.843.07 3.75Dissolved Metals Concentrations

During tests, samples were taken for fresh solvent at the beginning ofthe test runs and from spent solvent at the end of the test runs.Similar tests were carried out for MEA runs in 2013. A comparison of theresults of the APBS solvent and MEA tests is depicted in Table 11.

TABLE 11 Metal concentrations in solvents before and after the test runs(ppb wt). Fresh Fresh Rich Rich RCRA Metal MEA APBS MEAb APBSb LimitArsenic <12 53.2 219 114 5,000 Barium <12 <10 265 11.8 100,000 Cadmium<12 <5 <10 <5 1,000 Chromium <12 42.2 45,090 2,120 5,000 Selenium 44.141.8 1,950 660 1,000

As can be seen, the level of chromium for MEA was more than 22 timesthat in the APBS solvent, after two months of testing. This indicatesthat MEA is much more corrosive than the APBS solvent.

NCCC has concluded that the major source of selenium may be the fluegas. The inlet flue gas with APBS solvent testing was not sampled forselenium or other metals. However, since the coal used at the Gastonpower plant was from the same source, the metals level in the flue gaswould not have changed significantly from MEA tests in 2013 to those forAPBS in 2014. The level of selenium is three times higher in the MEAsample at the end of the runs, and this level (1,950 ppb wt) is almosttwice of the RCRA limit of 1,000 mg/L (which is the same as ppb wt for aliquid with specific gravity of 1.0).

CO2 Purity

The CO₂ stream after the condenser was analyzed and it was found to beconsistently higher than 97 vol % in CO₂ with about 2.5 vol % watervapor and 210 ppm N₂.

APES Emissions Testing

An analysis of amines and degradation products in the gas leaving thewater wash was conducted. The results are summarized in Tables 12 and 13below.

TABLE 12 Analysis of non-condensed vapor at wash tower outlet (May2015). Run Identification CCS- CCS- CCS- WTO-7 WTO-9 WTO-10 CompoundsAnalyzed All values in ppm wt Sum of nitrsoamines in Thermosorb N 0.00.0 0.0 tube, Sum of amines on sorbent tube SKC 2.62 9.75 2.60 226-30-18Sum of aldehydes on sorbent tube SKC 1.46 1.70 1.48 226-119 Totalhydrocarbons on sorbent tube 1.95 3.15 3.13 SKC 226-01 (as C6H6)

TABLE 13 Details of compounds analyzed for data in Table 11 (May 2015).Run Identification CCS- CCS- CCS- WTO-7 WTO-9 WTO-10 Aldehyde Profile onsorbent tube SKC 226-119 (rotameter #1); Detection Limit 0.5 μgAcetaldehyde, Total μg 22.7 36.3 1.23 Acrolein, Total μg BDL BDL BDLButyraldehyde, Total μg 3.46 12.1 0.482 Formaldehyde, Total μg 1.08 1.110.974 Glutaraldehyde, Total μg BDL BDL BDL Isovaleraldehyde, Total μgBDL BDL BDL Total Hydrocarbons on sorbent tube SKC 226-01 (rotameter#4); Detection Limit 1.0 μg Total Hydrocarbons as Hexane, Total μg 52.588.7 81.7 Amine Profile on sorbent tube SKC 226-30-18 (rotameter #5)Detection Limit 1.0 μg Allylamine, Total μg BDL BDL BDL Butylamine,Total μg BDL BDL BDL Dibutylamine, Total μg BDL BDL BDL Diethanolamine,Total μg BDL BDL BDL Diethylenetriamine, Total μg BDL BDL BDLDimethylamine, Total μg BDL BDL BDL Ethanolamine, Total μg 31.5 125 31.4Ethylamine, Total μg BDL 1.78 BDL Ethylenediamine, Total μg BDL 1.45 BDLIsopropylamine, Total μg BDL BDL BDL Methylamine, Total μg 3.68 2.851.16APES Nitrosamines Testing

Detailed Nitrosamine APBS solvent testing was performed. In all threesamples tested (CCS-WTO-7, CCS-WTO-8 and CCS-WTO-10), the values ofN-Nitroso-diethanolamine and a series of nitrosoamines were belowdetection limits of the two methods used. The results are summarized inTables 14 and 15 below.

TABLE 14 Test for N-Nitrosodiethanolamine by OSHA Method 31-Modified(April 2015). Detection Limit Concentration Sample ID (ug/tube)(ug/tube) CCS-WTO-7, -9 and -10 0.04 <0.04

TABLE 15 Results for Nitrosamines by NIOSH 2522-Modified (April, 2015).Detection Limit (ug/ Sample ID Analyte (ug/tube) tube) CCS-WTO-7, -9 and-IO N-Nitrosodimethylamine 0.02 <0.02 CCS-WTO-7, -9 and -ION-Nitrosomethylethylamine 0.02 <0.02 CCS-WTO-7, -9 and -ION-Nitrosodiethylamine 0.02 <0.02 CCS-WTO-7, -9 and -ION-Nitrosodi-n-propylamine 0.02 <0.02 CCS-WTO-7, -9 and -ION-Nitrosodi-n-butylamine 0.02 <0.02 CCS-WTO-7, -9 and -ION-Nitrosopiperidine 0.02 <0.02 CCS-WTO-7, -9 and -ION-Nitrosopyrrolidine 0.02 <0.02 CCS-WTO-7, -9 and -ION-Nitrosomorpholine 0.02 <0.02

Testing—Mt Biomethane Biogas Up-Gradation CO₂ Capture Pilot Plant-40 Vol% CO₂ Biogas

An APBS 40 vol % solvent test campaign was conducted at the MTBiomethane biogas up-gradation CO₂ capture pilot plant in Zeven,Germany. The APBS solvent was specifically developed to capture 40 vol %CO₂ from biogas. The MT Biomethane facility has a biogas up-gradationcapacity of 200 to 225 Nm³/hr. Agricultural waste is used to producebiogas using a digester. The heat needed for regeneration of the solventwas provided by hot water.

APES Testing: 40 Vol % CO₂ Capture Pilot Plant

The APBS testing was conducted from July 2014 to June 2015 for adetailed parametric test and baseline with an aMDEA solvent. After APBSwas used by the plant, CO₂ released through the absorber top wasnegligible. The methane rich stream leaving from the top of the absorbershould contain 2% mol of CO₂, hence all the optimization test wasconducted to meet this requirement.

Net Loading Capacity

It has been observed that the APBS solvent has a net loading capacityfor CO₂ 1.5 times higher than aMDEA. FIG. 15 illustrates the results ofa capacity comparison of aMDEA and APBS. As easily seen, APBS has ahigher capacity for CO₂ than does aMDEA. A higher capacity of a solventfor CO₂ leads to a decrease in circulation rate of the solvent, andhence a reduction in size of the equipment needed.

Recovery of Methane from Biagas

FIG. 9 illustrates methane recovery using APBS solvent. As APBS is inertto methane, the recovery from biogas is >99.9%.

Foaming

One of the major operational problems encountered by aMDEA was foamingonce a week, which lead to undue stoppage of plant operations and lossof processing of biogas, and hence revenue. In contrast, the use of APBSdid not result in any foaming in the absorber.

Energy

FIG. The average thermal energy for APBS is about 0.55 kWh/Nm³ of rawbiogas. The electrical energy was 0.1 kWh/Nm³ of raw biogas.

Make-Up Chemicals

Over a period of time, due to vapor pressure and degradation,performance of aMDEA starts to diminish. Thus, a regular make-up ofchemicals are needed to achieve required performance using aMDEA. In thecase of APBS, it has been observed that there is no need for make-upchemicals. FIG.

MT Biomethane Biagas Up-Gradation CO₂ Capture Pilot Plant Testing

Use of APBS leads to savings in thermal and electrical energy up toabout 20% and to about 40%, respectively. Since APBS did not lead to asingle occurrence of foaming, APBS can increase productivity of biogasprocessing. Due to higher solvent life and very low corrosion rate, theoverall investment over the plant life can be decreased by using APBS.

What is claimed is:
 1. A method for removing CO₂ from a CO₂-containinggas, the method comprising: contacting an aqueous solvent with theCO₂-containing gas to dissolve the CO₂ in the aqueous solvent, whereinthe aqueous solvent has 2-amino-2-methylpropanol from 10% to 32% of thesolvent by weight, 2-piperazine-1-ethylamine from 10% to 35% of thesolvent by weight, diethylenetriamine from 0.1% to 4% of the solvent byweight, 2-methylamino-2-methyl-1-propanol from 0.8% to 5% of the solventby weight, and a potassium carbonate buffer, wherein the2-piperazine-1-ethylamine and the diethylenetriamine together have vaporpressure less than 0.009 kPa at 25 C, wherein the2-methylamino-2-methyl-1-propanol and 2-methylamino-2-methyl-1-propanoltogether have a vapor pressure less than 0.1 kPa at 25 C.
 2. The methodin claim 1, wherein the aqueous solvent has vapor pressure less than1.85 kPa at 25 C.
 3. The method of claim 1, wherein the CO₂-containinggas comprises waste from a combustion process and the process is used toremove a carbon-containing compound in a post-combustion carbon captureprocess.
 4. The method of claim 1, wherein the CO₂-containing gas is aflue gas or waste from a combustion process.
 5. The method of claim 1,wherein the 2-amino-2-methylpropanol is about 19.5% of the solvent byweight, the 2-piperazine-1-ethylamine is about 22.4% of the solvent byweight, the diethylenetriamine is about 0.2% of the solvent by weight, a2-methylamino-2-methyl-1-propanol is about 1.4% of the solvent byweight, and a carbonate buffer, wherein the solvent has a vapor pressureless than 1.85 kPa at 25 C.
 6. The method of claim 1, wherein the2-piperazine-1-ethylamine is between 12% and 30% of the solvent byweight, and the diethylenetriamine is between 0.1% and 0.35% of thesolvent by weight.
 7. The method of claim 1, wherein the2-amino-2-methylpropanol, 2-piperazine-1-ethylamine, diethylenetriamine,and 2-methylamino-2-methyl-1-propanol together exhibit substantially nofoaming when contacted with the CO₂-containing gas.
 8. The method ofclaim 1, wherein the 2-methylamino-2-methyl-1-propanol is about 2% ofthe solvent by weight.
 9. The method of claim 1, wherein the potassiumcarbonate buffer is about 0.1% to about 6% of the solvent by weight.